Gas wells, and in particular sour gas wells with varying quantities of H2S are produced throughout the Western Canada Sedimentary Basin. Even when reservoir pressures deplete, the remaining gas volumes left in the reservoir are usually significant. The challenge is to produce the remaining reserves with low flowing pressures and inconsistent production line pressures.
Sour gas wells are typically completed with a packer in place to isolate the sour production from the annular space between the well casing inside diameter and the outside diameter of the production tubing. The packer prevents sour gas from entering the annulus and corroding the casing string, which is the barrier between the wellbore and any adjacent ground water or aquifer. Additionally, the annulus above the packer is typically filled with inhibited brine solution to enhance corrosion protection and provide an additional barrier preventing migration of sour gas into the annulus.
All gas wells will produce a quantity of liquid during gas production. Liquid loading is a symptom of the well's inability to unload liquids that are naturally produced during the production life of the well and is the most common cause of production decline in a gas well. In addition to liquid loading, there are a number of other reasons why wells will not produce at the maximum level. If a number of wells are drilled into the same reservoir and the gas is depleted at a faster than normal rate, the competitive drainage of the reservoir will reduce production. In a compartmentalized reservoir, where reservoir size is limited because of lack of connectivity between the permeable parts of the formation, there may be production issues. Also, production may be limited because of formation damage caused to the near well bore while drilling the well or on subsequent work over with a service rig or natural near well bore damage may also be caused by liquid loading or natural scaling effects of the produced well effluent.
When a well is initially drilled, it is typically in a virgin part of the reservoir, and therefore reservoir pressures and volumes are usually quite high. The surface production lines that will transport the gas and liquids are operated at pressures that allow the well to flow to surface. The difference between the surface lines pressure and the flowing bottom hole pressure of the well will dictate how much the well can flow. Other factors also relate directly to this such as gas density, friction effect, liquid density and depth of the well. As the well ages and flowing bottom hole pressure depletes, the well will experience reduced flow capability.
It is well known that liquid loading affects gas production when gas velocity drops below the level necessary to carry liquid droplets upwards, known as the critical gas velocity. Critical gas velocity is a function of flowing pressure, fluid and gas density, droplet size, surface tension, temperature and pipe diameter.
One method of increasing gas velocity is to change tubular size or decrease surface pressure, and the effect on the wells ability to unload liquid can be dramatic when such solutions are applied. However, these solutions will only last as long as the bottom reservoir pressure can produce against the new conditions.
Unfortunately for most sour gas wells, the option to change tubulars or decrease surface pressures is often uneconomic, and the well is abandoned long before its usable reserves are depleted. The cost to change out tubulars is high (rig, safety equipment, pump trucks etc.) and there is a significant risk of potential damage to the formation, which may occur as the well has to be killed using a fluid having hydrostatic weight equal or greater than the shut in reservoir pressure. In many cases the depth of the well and the low reservoir pressure will not hold a full column of kill fluid and the fluid will fracture into the formation face, causing damage that cannot be repaired.
Surface pressure may be reduced by using a compressor to reduce the flowing wellhead pressure in the wellbore. The cost is directly related to the size of compressor required to have sufficient suction pressure that allows the well to unload liquid with the elevated velocity required to produce the gas to the gathering system lines. Most compressors for sour gas are required to have numerous safety shutdown systems and expensive coolers to reduce the heat of compressed gas and noise emission controls.
Artificial lift in these wells is difficult to implement. Most types of downhole mechanical or electrical pumps do not work well in a high gas environment due to gas locking and cavitation. The costs of the modifications or additional completion components required to adapt the pumping systems to efficient operation in high gas ratio environments can also be prohibitively expensive.
Therefore, there is a need in the art for an innovative and economical solution to produce gas from these aging reservoirs.